UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549



FORM 10-Q

ý

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended September 30, 2011Oro

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period
from                                    to


Commission File Number: 0-06910



TEL OFFSHORE TRUST

(Exact name of registrant as specified in its charter)

Texas(State or other jurisdiction
of incorporation or organization)

76-6004064(I.R.S. Employer Identification No.)The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue
Austin, Texas(Address of principal executive offices)

78701(Zip Code)


(800) 852-1422(Registrant's telephone number, including area code)

Indicate
by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes ý    No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter
period that the registrant was required to submit and post such
files). Yes o    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o

Accelerated filer o

Non-accelerated filer ý (Do not check if a
smaller reporting company)

Smaller reporting company o


Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes o    No ý

As of November 11, 2011, 4,751,510 Units of Beneficial Interest in TEL Offshore Trust were outstanding.



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NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act
of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-Q
are forward-looking statements. Although Chevron USA, Inc., the Managing General Partner of the TEL Offshore Trust Partnership, has advised the Trust that the Managing General Partner believes
that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can be given that such expectations will prove to have been correct. Important factors
that could cause actual results to differ materially from expectations ("Cautionary Statements") are disclosed in this Form 10-Q, including, without limitation, in conjunction with
the forward-looking statements included in this Form 10-Q. A summary of certain principal risks and Cautionary Statements is also included in the Trust's Annual Report on
Form 10-K for the year ended December 31, 2010 under Part I, Item 1A "Risk Factors" and in Part II, Item 1A of this Form 10-Q.
All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements.

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PART IFINANCIAL INFORMATION

Item 1.    Financial Statements.

TEL OFFSHORE TRUST  STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS  (Unaudited)

September 30,
2011

December 31,
2010AssetsCash and cash equivalents

$
6,580

$
352,017Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,247,172 and $28,245,160, respectively


20,483


22,495Total assets

$
27,063

$
374,512Liabilities and Trust CorpusDistribution payable to Unit holders

$


$
Reserve for future Trust expenses


6,580


352,017Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding)


20,483


22,495Total liabilities and Trust corpus

$
27,063

$
374,512


STATEMENTS OF DISTRIBUTABLE INCOME  (Unaudited)

Three Months Ended
September 30,

Nine Months Ended
September 30,2011

2010

2011

2010Royalty income

$


$


$


$
Interest income


1


20


13


1681


20


13


168Decrease in reserve for future Trust expenses


41,045


237,784


345,438


689,929General and administrative expenses


(41,046
)

(237,804
)

(345,451
)

(690,097
)Distributable income











Distributions per Unit (4,751,510 Units)

$
.000000

$
.000000

$
.000000

$
.000000


STATEMENTS OF CHANGES IN TRUST CORPUS  (Unaudited)

Three Months Ended
September 30,

Nine Months Ended
September 30,2011

2010

2011

2010Trust corpus, beginning of period

$
21,186

$
24,611

$
22,495

$
27,186Distributable income











Distribution payable to Unit holders











Amortization of net overriding royalty interest


(703
)

(1,242
)

(2,012
)

(3,817
)Trust corpus, end of period

$
20,483

$
23,369

$
20,483

$
23,369


The
accompanying notes are an integral part of these financial statements.

1

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TEL OFFSHORE TRUST        NOTES TO FINANCIAL STATEMENTS        (Unaudited)

Note 1Trust Organization

Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of Dissolution ("Plan")
approved by Tenneco Offshore's stockholders on December 22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership ("Partnership") was formed in which the Trust owns a 99.99%
interest and Tenneco Oil Company initially owned a .01% interest. In general, the Plan was effected by transferring an overriding royalty interest ("Royalty") equivalent to a 25% net profits interest
in the oil and gas properties (the "Royalty Properties") of Tenneco Exploration, Ltd. located offshore Louisiana to the Partnership and issuing certificates evidencing units of beneficial
interest in the Trust ("Units") in liquidation and cancellation of Tenneco Offshore's common stock.

On
January 14, 1983, Tenneco Offshore distributed Units to holders of Tenneco Offshore's common stock on the basis of one Unit for each common share owned on such date.

The
terms of the Trust Agreement, dated January 1, 1983, provide, among other things, that:



2

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1Trust Organization (Continued)

The
Trust is currently administered by The Bank of New York Mellon Trust Company, N.A. (the "Corporate Trustee"), which succeeded JPMorgan Chase Bank, N.A. as the corporate trustee,
effective October 2, 2006 pursuant to an agreement under which The Bank of New York acquired substantially all of the corporate trust business of JPMorgan Chase (formerly known as The Chase
Manhattan Bank), and Gary C. Evans, Thomas H. Owen, Jr., and Jeffrey S. Swanson (the "Individual Trustees"), as trustees (the "Trustees").

Note 2Basis of Accounting and Going Concern

The accompanying unaudited financial information has been prepared by the Corporate Trustee. The accompanying financial information is prepared on a comprehensive basis of accounting
other than accounting principles generally accepted in the United States of America ("generally accepted accounting principles"). The Corporate Trustee and the Individual Trustees believe that the
information furnished reflects all adjustments that are, in the opinion of the Trustees, necessary for a fair presentation of the results for the interim periods presented. Such adjustments are of a
normal and recurring nature. The financial information should be read in conjunction with the financial statements and notes thereto included in the Trust's Annual Report on
Form 10-K for the year ended December 31, 2010.

The
financial statements of the Trust are prepared on the following basis:



This
manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the
Working Interest Owners. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles, because, under such principles,
Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, which is
calculated on a units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income.

3

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2Basis of Accounting and Going Concern (Continued)

On
the last business day of each calendar quarter prior to August 1, 2011, the Working Interest Owners were to pay to the Partnership 25% of the Net Proceeds (as defined below in
Note 3) for the immediately preceding Quarterly Period. As discussed in Note 7Subsequent Events, on October 27, 2011, but effective as of August 1, 2011, the
Partnership sold 20% of the Royalty to a third party; as a result, on the last business day of each calendar quarter after August 1, 2011, the Working Interest Owners are to pay to the
Partnership 80% of the Net Proceeds for the immediately preceding Quarterly Period. A Quarterly Period is each period of three months commencing on the first day of February, May, August and November.
In turn, the Partnership distributes funds to its partners on the last business day of each calendar quarter. Cash distributions from the Trust are made in January, April, July and October of each
year, and are payable to Unit holders of record as of the last business day of each calendar quarter. Thus, any cash conveyed to the Trust from the Royalty during the quarter ended
September 30, 2010 would substantially represent the revenues and expenses from the Royalty Properties from May 2010 through July 2010. Similarly, any cash conveyed to the Trust from the
Royalty during the quarter ended September 30, 2011 would substantially represent the revenues and expenses from the Royalty Properties from May 2011 through July 2011. However, there was no
cash conveyed to the Trust from the Royalty Properties from either May 2010 through July 2010 or May 2011 through July 2011. The financial and operating information included in this
Form 10-Q for the three months ended September 30, 2011 and September 30, 2010 represents financial and operating information with respect to the Royalty Properties
for the immediately preceding months of May, June and July. Similarly, financial and operating information with respect to the Royalty Properties for the nine months ended September 30, 2011
and September 30, 2010 represents financial and operating information with respect to the Royalty Properties for the immediately preceding months of November through July. Income from the
Royalty is recorded by the Trust on a cash basis, when it is received by the Trust from the Partnership.

Cash
and cash equivalents include all highly liquid, short-term investments with original maturities of three months or less.

The
changes in reserve for future Trust expenses represent amounts paid from the reserve during periods when the Trust had insufficient income to pay Trust expenses.

The
Trust reviews the net overriding royalty interest in oil and gas properties for possible impairment whenever events or circumstances indicate the carrying amount of the asset may not
be recoverable. If there is an indication of impairment, the Trust prepares an estimate of future cash flows (undiscounted and without interest charges) expected to result from the use of the asset
and its eventual disposition. If these cash flows are less than the carrying amount of the asset, an impairment loss may be recognized to write down the asset to the lower of its estimated fair value
or net book value.

4

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2Basis of Accounting and Going Concern (Continued)

Preparation
of estimated expected future cash flows is inherently subjective and is based on the Corporate Trustee's best estimate of assumptions concerning expected future conditions.
There were no write downs taken in the periods presented.

The
Special Cost Escrow account (See Note 5) is established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other
production facilities and for the estimated amount of future capital expenditures on the Royalty Properties. The funds held in the Special Cost Escrow account are not reflected in the financial
statements of the Trust. However, funds deposited to or released from the Special Cost Escrow account are included in the Royalty income.

The
preparation of financial statements requires the Trustees to make use of estimates and assumptions that affect amounts reported in the financial statements as well as certain
discounts. Actual results could differ from those estimates.

The
amount of cash distributions by the Trust is dependent on, among other things, the sales prices for oil and gas produced from the Royalty Properties and the quantities of oil and gas
sold. It should be
noted that substantial uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions taken
by major petroleum producing nations, as well as the regional supply and demand for gas, weather, industrial growth, conservation measures, competition, economic conditions generally and other
variables. The Trust does not enter into any hedging transactions on future production.

The
Corporate Trustee has evaluated subsequent events through the date that these financial statements were issued.

Going Concern Uncertainty

The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. The lack of Net
Proceeds and the inability to maintain adequate cash reserves raise substantial doubt about the Trust's ability to continue as a going concern (see Notes 4 and 6). Certain potential
alternatives available to the Trustees are described in Note 7. The Trust may also borrow funds. The financial statements do not include any adjustments that might result from the outcome of
this uncertainty.

Note 3Net Overriding Royalty Interest

The Royalty entitles the Trust to its share (99.99%) of 25% of the Net Proceeds attributable to the Royalty Properties; such percentage of Net Proceeds is 20% effective as of
August 1, 2011 due to a sale by the Partnership of a portion of the Royalty. See Note 7Subsequent Events. The Conveyance, dated January 1, 1983, provides that the
Working Interest Owners will calculate, for each period of three months commencing the first day of February, May, August and November, an amount equal to

5

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 3Net Overriding Royalty Interest (Continued)

25%
of the Net Proceeds from their oil and gas properties for the period. Generally, "Net Proceeds" means the amounts received by the Working Interest Owners from the sale of minerals from the Royalty
Properties less operating and capital costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and
a Special Cost Escrow account. The Special Cost Escrow account (See Note 5) is established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms,
pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. Net Proceeds do not include amounts received by the Working Interest
Owners as advance gas payments, "take-or-pay" payments or similar payments unless and until such payments are extinguished or repaid through the future delivery of gas.

Note 4Distributions to Unit Holders

In accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and any cash reserves
established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. Such distributions are referred to as "distributable income." The amounts
distributed are determined on a quarterly basis and are payable to Unit holders of record as of the last business day of each calendar quarter. However, cash distributions are made in January, April,
July and October and include interest earned from the quarterly record date to the date of distribution.

Set
forth below are the quarterly distributions made by the Trust for 2011 and 2010.

Quarter

Distribution2011:Third

$
0Second


0First


02010:Fourth

$
0Third


0Second


0First


0


Production
ceased at Eugene Island 339 and Ship Shoal 182 and 183 following damages inflicted by Hurricane Ike in September 2008. Future Net Proceeds may take into account the Trust's
share of project costs and other related expenditures that are not covered by insurance of the operator of the Royalty Properties. On March 25, 2009, the Trust announced that there would be no
trust distribution for the first quarter of 2009, and the Trust has not made a distribution since January 9, 2009.

6

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 4Distributions to Unit Holders (Continued)

There
are not likely to be sufficient Net Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly distribution to Unit holders for the foreseeable
future. As a result of the damage inflicted by Hurricane Ike, Net Proceeds will continue to be severely impacted by reduced production, from historical levels, and the amount of expenditures incurred
that are associated with such damages, including the expenditures required to plug and abandon the wells on Eugene Island 339 and, as currently expected, to redevelop the facility at Eugene Island
339. While Chevron has stated that it intends to redevelop Eugene Island 339, there is no obligation for Chevron to continue to pursue such redevelopment. Chevron offered to the Trustees in February
2011 that, based on then present production forecasts, the possibility of distributions being made to the Partnership would likely begin in 2013. However, there can be no assurance by Chevron or
anyone else as to the actual timing for any future distributions to the Partnership from the Royalty, and distributions could recommence some time before, during or after 2013, and there is no
guarantee that any further distributions will be made. Future Net Proceeds from the Royalty Properties will take into account the Trust's share of project costs and other related expenditures that are
not covered by the insurance of the operators of the Royalty Properties. In September 2011, Chevron informed the Trust that the estimate of the Trust's net portion of the aggregate cost to plug and
abandon the wells subject to the Royalty on Eugene Island 339 had increased from approximately $15 million to approximately $16.5 million, approximately $14.2 million of which had
been incurred through July 31, 2011, and without giving credit for an expected approximately $612,000 of insurance proceeds received. If development and production costs of the Royalty
Properties exceed the proceeds of production from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus
accrued interest. As a result of the damage inflicted by Hurricane Ike, the Trust has not received Net Proceeds since December 2008. As of July 31, 2011, aggregate development and production
costs for the Royalty Properties since November 2008 have exceeded the related proceeds of production from the Royalty Properties by approximately $4.2 million. In the fourth quarter of 2010,
Chevron withdrew $4,304,894 from the Special Cost Escrow account of the Working Interest Owners to cover expenses incurred in connection with the plugging and abandonment of Eugene Island 339, which
served to reduce the amount by which development and production costs exceeded the related proceeds of production as of December 31, 2010. Significant redevelopment costs will be incurred if
Eugene Island 339 is redeveloped; however, Chevron has entered into a participation agreement with a third party whereby the third party has the right to earn an assignment of 65% of Chevron's working
interest in the Eugene Island properties, and neither Chevron nor the Trust would, except in the event of any amendment of the participation agreement, bear the cost of the redevelopment of Eugene
Island 339. Accordingly, there will not be sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future. At this time, the ultimate outcome of these
matters cannot be determined with any degree of certainty.

7

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 5Special Cost Escrow Account

The Special Cost Escrow is an account of the Working Interest Owners, and it is described herein for informational purposes only. The Conveyance provides for the reserve of funds for
estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling
projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based on certain factors, including estimates of
aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net profits interest. Deposits into this account reduce current distributions and
are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow" account. The Trust's share of interest
generated from the Special Cost Escrow account serves to reduce the Trust's share of allocated production costs. Special Cost Escrow funds will generally be utilized to pay Special Costs to the extent
there are not adequate current net profits interest to pay such costs. Special Costs that have been paid are no longer included in the Special Cost Escrow calculation. Deposits to the Special Cost
Escrow account will generally be made when the balance in the Special Cost Escrow account is less than 125% of estimated future Special Costs and there is a Net Revenues Shortfall (a calculation of
the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When there is not a Net Revenues Shortfall, amounts in the Special Cost
Escrow account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost Escrow account will also be released when the balance in such account
exceeds 125% of estimated future Special Costs.

In
the fourth quarter of 2010, Chevron withdrew $4,304,894 from the Special Cost Escrow account of the Working Interest Owners (a reserve fund for certain costs) to cover expenses
incurred in connection with the plugging and abandonment of Eugene Island 339, leaving a balance of $1,000 in the Special Cost Escrow account. After taking into account such withdrawal, aggregate
development and production costs in excess of the related proceeds for the royalty properties, as of July 31, 2011, was approximately $4.2 million, net to the royalty interest; however,
additional deposits to the Special Cost Escrow account would be required in future periods in accordance with the underlying conveyance of the royalty if, and when, net proceeds would otherwise be
payable on the royalty. In the third quarter of 2011, there were no funds released from or escrowed into the Special Cost Escrow account. As of September 30, 2011, $1,000 remained in the
Special Cost Escrow account. None of the funds held in the Special Cost Escrow account are reflected in the financial statements of the Trust.

In
connection with the sale of 20% of the Royalty by the Partnership in October 2011, the Partnership also assigned 20% of its rights and obligations with respect to the Special Cost
Escrow. See Note 7Subsequent Events.

Chevron
USA, Inc. ("Chevron"), in its capacity as Managing General Partner of the Partnership, has advised the Trust that additional deposits to the Special Cost Escrow account
may be required in future periods in connection with other production costs, other abandonment costs, other capital

8

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 5Special Cost Escrow Account (Continued)

expenditures
and changes in the estimates and factors described above. Such deposits could result in a significant reduction in Royalty income in the periods in which such deposits are made, including
the possibility that no Royalty income would be received in such periods.

Note 6Reserve For Future Trust Expenses

The Trust generally maintains a cash reserve, equal to approximately three times the average annual expenses of the Trust during each of the then past three years, to provide for future
administrative expenses in connection with the winding up of the Trust. However, as a result of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in September 2008, the
Trust has not received sufficient Net Proceeds to maintain the reserve at such level. During the third quarter of 2011, the Trust used approximately $41,046 from the reserve account for current
expenses, leaving a reserve balance as of September 30, 2011 of approximately $6,580, or approximately 1% of the average annual expenses of the Trust during the three-year period
ended September 30, 2011. As of September 30, 2011, the Trust had additional expenses of approximately $432,000 in the aggregate that had not been paid. During the third quarter of 2010,
the Trust used $237,784 from the reserve account for current expenses, leaving a reserve balance as of September 30, 2010 of $573,151, or approximately 67% of the average annual expenses of the
Trust during the three-year period ended September 30, 2010.

There
are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. Chevron offered to the Trustees in February 2011 that, based on then present
production forecasts, the possibility of distributions being made to the Partnership would likely begin in 2013. However, there can be no assurance by Chevron or anyone else as to the actual timing
for any future distributions to the Partnership from the Royalty, and distributions could recommence some time before, during or after 2013, and there is no guarantee that any further distributions
will be made.

Note 7Subsequent Events

Because of the lack of receipt of Net Proceeds, the Trust has not had sufficient cash flow to pay expenses on a current basis. The Trust Agreement provides that, if necessary to provide
for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders (a) sell all or a portion of the Trust's interest in the Partnership or any
other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise their rights under the Partnership Agreement to dissolve the Partnership, or
(c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

On
March 11, 2011, the Trustees provided written notice to Chevron that, pursuant to the Trust Agreement, the Trust needed funds to pay for liabilities of the Trust and that the
Trustees therefore instructed Chevron, as the Managing General Partner of the Partnership, to sell such portion, and only such portion, of the Royalty that will provide the Trust with a current
distribution equal to $2,000,000

9

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TEL OFFSHORE TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 7Subsequent Events (Continued)

from
the proceeds of such sale. Based on a recommendation from Chevron, as the Managing General Partner of the Partnership, Chevron marketed for sale by the Partnership the entire Royalty, while
reserving the right to sell only a portion of the Royalty. Chevron engaged EnergyNet.com, Inc. to conduct the marketing process and the related auction for the Royalty, with the bids in the
auction due on August 30, 2011. EnergyNet.com, Inc. is a FINRA-registered broker dealer that provides marketing services to the oil and gas industry.

On
October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale of 20% of the Royalty. The sale generated $1,600,000 in gross
proceeds and
occurred as part of such formal auction process for the Royalty. The Trust received from the Partnership a distribution of approximately $1,485,851, representing 99.99% of the net proceeds from the
sale of $1,486,000. The Trust will use such net proceeds solely for the payment of expenses of the Trust.

The
sale is governed by a letter agreement, pursuant to which the Partnership and RNR Production, Land and Cattle Company, Inc. ("Purchaser") made various representations and
warranties, with related indemnification obligations. In connection therewith, the Partnership and Purchaser executed a Partial Assignment of Overriding Royalty Interests.

The
sale was made to Purchaser on October 27, 2011, though the assignment of the 20% is effective as of August 1, 2011. Purchaser initially required a minimum purchase of
25% of the Royalty. Pursuant to an Option Agreement, the Partnership has agreed with Purchaser that if the Partnership elects to sell, or market for sale, any portion of the Royalty on or prior to
December 31, 2012, Purchaser will have the option to acquire such percentage interest, up to an additional 5% of the entire Royalty, for a sales price equivalent to the product of $80,000 times
the percentage interest acquired. In order to exercise the option, Purchaser would have to provide the Partnership notice of such exercise within 10 days following the Partnership's notice to
Purchaser of such proposed sale.

10

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations.

Critical Accounting Policies

The financial statements of the Trust are prepared on the following basis:



This
manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the
Working Interest Owners. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles, because, under such principles,
Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, calculated on a
units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income.

The
Trustees, including the Corporate Trustee, have no authority over, have not evaluated and make no statement concerning, the internal control over financial reporting of the Working
Interest Owners.

Financial Review

In January 2010, the Trust engaged an independent oil and gas accounting firm to review the books and records of certain Working
Interest Owners with respect to the Royalty Properties and the related payments to the Trust. Such audit review process is currently on-going and may result in certain adjustments to
revenues, production volumes, prices and expenditures. As part of such process, Chevron has agreed that $22,197 in adjustments were appropriate, which were credited in the first quarter of 2011.
Chevron did not pay this amount to the Partnership or the Trust, but credited such amount against the Partnership's share of allocated expenses for the Royalty Properties. Chevron has also agreed that
$608,409 of expenses with respect to Eugene Island 339 in the first quarter of 2009 that were previously allocated to the Partnership should have been charged to Chevron. Credit for $287,594 of such
amount was made in the second quarter of 2011, with the remaining $320,815 credited in the third quarter of 2011. No assurance can be provided as to the ultimate outcome of such audit review process.

Three Months Ended September 30, 2011 and 2010

There were no distributions to the Unit holders for the three months ended September 30, 2011 and 2010.

11

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Crude
oil and condensate revenues increased $1,661,678, or 49%, to $5,082,567 in the third quarter of 2011 from $3,420,889 in the third quarter of 2010. Oil volumes during the third
quarter of 2011 increased 1% to 43,221 barrels, compared to 42,811barrels of oil produced in the third quarter of 2010. The average price received for crude oil and condensate increased 47%, or
$37.68, to $117.59 per barrel in the third quarter of 2011 from $79.91per barrel in the third quarter of 2010.

Gas
revenues decreased $106,355, or 44%, to $132,665 in the third quarter of 2011 from $239,020 in the third quarter of 2010. Gas volumes during the third quarter of 2011 decreased 47%
to 27,692 Mcf, compared to 52,524 Mcf produced in the third quarter of 2010. The decrease in volumes is primarily due to an adjustment that was made to correct volumes and values reported in a prior
quarter as well as normal fluctuations in production. The average price received for natural gas was $4.79 per Mcf in the third quarter of 2011 compared to $4.55 per Mcf in the third quarter of 2010.
Gas products revenue decreased $41,013, or 69%, to $18,542 in the third quarter of 2011 from $59,555 in the third quarter of 2010. Gas products volumes during the third quarter of 2011 decreased 76%
to 14,597 gallons, compared to 60,757 gallons in the third quarter of 2010.

Capital
expenditures increased by $140,642, or 77%, from $185,785 in the third quarter of 2010 to $326,427 in the third quarter of 2011. The higher amount of capital expenditures during
the third quarter of 2011 relate to certain facility improvement projects at Ship Shoal 182/183.

Operating
expenses decreased by $435,609, or 6%, from $7,115,834 in the third quarter of 2010 to $6,680,225 in the third quarter of 2011. The decrease in operating expenses is due
primarily to less well and platform abandonment work being conducted at Eugene Island 339 in the third quarter of 2011 as compared to the third quarter of 2010. Reflected within the operating expenses
are management fees
to Chevron, as Managing General Partner of the Partnership, of $321,243 and $356,517 in the third quarter of 2010 and 2011, respectively.

The
Royalty Properties had undistributed net loss of $1,798,460 in the third quarter of 2011.

In
the third quarter of 2011, there were no funds released from or escrowed into the Special Cost Escrow account. As of September 30, 2011, $1,000 remained in the Special Cost
Escrow account. None of the funds held in the Special Cost Escrow account are not reflected in the financial statements of the Trust. The Special Cost Escrow account is set aside for estimated
abandonment costs and future capital expenditures, as provided for in the Conveyance. For additional information relating to the Special Cost Escrow account, see "Special Cost Escrow
Account" below.

In
the third quarter of 2010, there were no funds released from or escrowed into the Special Cost Escrow account. As of September 30, 2010, $4,306,846 remained in the Special Cost
Escrow account.

Nine Months Ended September 30, 2011 and 2010

There were no distributions to the Unit holders for the nine months ended September 30, 2011 and 2010.

Crude
oil and condensate revenues increased $2,712,263, or 28%, to $12,288,631 in the first nine months of 2011 as compared to $9,576,368 for the same period in 2010, due primarily to
increased realized prices. Oil volumes decreased 5% to 117,850 barrels in the first nine months of 2011 from 123,586 barrels in the first nine months of 2010. Production ceased at Ship Shoal 182/183
for 36 days starting in late March 2010 due to a leak in the oil pipeline that services Ship Shoal 182/183. Ship Shoal was again shut-in during November 2010 for a tank replacement
and production slowly returned

12

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thereafter.
The average price received for crude oil and condensate increased 35%, or $26.78, to $104.27 per barrel in the first nine months of 2011 from $77.49 per barrel in the first nine months of
2010.

Gas
revenues decreased $570,984, or 54%, to $478,705 in the first nine months of 2011 from $1,049,689 for the same period in 2010. Gas volumes decreased 45% to 114,180 Mcf in the first
nine months of 2011 from 209,345 Mcf for the same period in 2010. Production ceased at Ship Shoal 182/183 for 36 days starting in late March 2010 due to a leak in the oil pipeline that services
Ship Shoal 182/183. Ship Shoal was again shut-in during November 2010 for a tank replacement and production slowly returned thereafter. The decrease in volumes is also partially due to an
adjustment that was made to correct volumes and values reported in a prior quarter as well as normal fluctuations in production. The average price received for natural gas decreased 16%, or $0.82, to
$4.19 per Mcf in the first nine months of 2011 from $5.01 per Mcf in the same period of 2010. Gas products revenue decreased $130,290, or 73%, to $47,487 in the first nine months of 2011 from $177,777
in the same period of 2010, primarily due to a decrease in production volume of 117,454 gallons, or 77%, to 35,449 gallons in the first nine months of 2011 from 152,903 gallons in the same period of
2010.

Capital
expenditures increased $710,884, or 252%, from $281,778 the first nine months of 2010 to $992,662 in the same period of 2011. The higher amount of capital expenditures during the
first nine months of 2011 relate primarily to tank and panel upgrades at Ship Shoal 182/183.

Operating
expenses increased by $853,280, or 6%, from $14,948,367 in the first nine months of 2010 to $15,801,647 in the first nine months of 2011, due primarily to increased well and
platform abandonment work being conducted at Eugene Island 339 in the second quarter of 2011 as compared to the second quarter of 2010. Reflected within the operating expenses are management fees to
Chevron, as Managing General Partner of the Partnership, of $758,946 and $862,402 for the first nine months of 2010 and the first nine months of 2011, respectively.

The
Royalty Properties had undistributed net loss of $4,042,141 for the nine months ended September 30, 2011.

In
the first nine months of 2011 and 2010, no funds were released or escrowed from the Special Cost Escrow account.

Reserve for Future Trust Expenses

In accordance with the provisions of the Trust Agreement, generally all Royalty income received by the Trust, net of Trust general and
administrative expenses and any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. The Trust has previously
determined that a cash reserve equal to approximately three times the average annual expenses of the Trust during each of the then past three years was sufficient to provide for future administrative
expenses in connection with the winding up of the Trust. However, as a result of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in September 2008, the Trust has not
received sufficient Net Proceeds to maintain the reserve at such level. During the third quarter of 2011, the Trust used approximately $41,046 from the reserve for current expenses, leaving a reserve
balance as of September 30, 2011 of approximately $6,580, or approximately 1% of the average annual expenses of the Trust during the three-year period ended September 30,
2011. As of September 30, 2011, the Trust had additional expenses of approximately $432,000 in the aggregate that had not been paid. The reserve amount at December 31, 2010 was $352,017,
or approximately 39% of

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the
average annual expenses of the Trust during the three-year period ended December 31, 2010. However, in connection with the sale of 20% of the Royalty by the Partnership in
October 2011, the Trust received a distribution of approximately $1,485,851, representing 99.99% of the net proceeds from the sale of $1,486,000. The Trust will use such net proceeds solely for the
payment of expenses of the Trust.

Other

The amount of cash distributed by the Trust is dependent on, among other things, the sales prices and quantities of oil and gas
produced from the Royalty Properties as well as expenditures by the Working Interest Owners that may or may not be included in the Special Cost Escrow account. It should be noted that substantial
uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions taken by major petroleum
producing nations, as well as the regional supply and demand for oil and gas, weather, industrial growth, conservation measures, competition, economic conditions generally and other variables.

Operational Review

The following operational information has been based on information provided to the Corporate Trustee by Chevron as the Managing
General Partner of the Partnership. The Trustees have no control over these operations or internal controls relating to this information.

The
platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike in September 2008. Crude oil revenues from Eugene Island 339 represented approximately 48% of the
crude oil and condensate revenues for the Royalty Properties in 2007 and approximately 47% of such revenues for the nine months ended September 30, 2008. Eugene Island 339 contributed
approximately 12% of the revenues from natural gas sales from the Royalty Properties in 2007 and approximately 41% of such revenues for the nine months ended September 30, 2008. Based on a
prior year reserve study prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants, Eugene Island 339 accounted for approximately 34% of the total future net revenues
attributable to the Partnership's interest in the Royalty as of October 31, 2007. Chevron is still working on the plugging and abandonment of the existing wells, clearing debris and otherwise
dealing with the remaining infrastructure, which activities are not expected to be completed until the second quarter of 2012. In September 2011, Chevron informed the Trust that the estimate of the
Trust's net portion of the aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased from approximately $15 million to approximately
$16.5 million, approximately $14.2 million of which had been incurred through July 31, 2011, and without giving credit for an expected approximately $612,000 of insurance proceeds
received, or to be received, by Chevron.

Generally,
if production ceases from an outer continental shelf lease, like that for Eugene Island 339, production must be restored or drilling operations must commence within
180 days of the cessation of production (which was in early March 2009 with respect to Eugene Island 339 given the cessation of production in September 2008 resulting from Hurricane Ike), or
the lease will be terminated. Alternatively, an operator of a lease may seek a Suspension of Production, or "SOP", that, if approved by the regional supervisor of the BOEM, allows additional time to
restore production in the event of certain circumstances, such as hurricanes and other events beyond the control of the operator. Chevron, as the operator of Eugene Island 339, sought and obtained an
SOP for Eugene

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Island
339 for the period from December 1, 2010 through October 31, 2011. Chevron had previously sought and obtained an SOP providing for the staged redevelopment of Eugene Island 339
and the adjacent lease, Eugene Island 338 (which is not a Royalty Property), as a single development project, contingent upon meeting certain obligations established in the SOP. The initial SOP
extended the lease
on Eugene Island 339 until November 30, 2010. A subsequent SOP extended the lease from December 1, 2010 through October 31, 2011, as long as certain SOP milestones were met. The
first milestone, "issue Jacket and Pile Material Order (MTO) Drawings to fabrication contractor", due prior to April 30, 2011, was met and Chevron so informed the BOEM. The second milestone,
"continuation of offshore deck refurbishment," due prior to May 30, 201, was met and Chevron so informed the BOEM. Additional SOP milestones included a report on deck refurbishment due prior to
August 30, 2011, and commencement of jacket and pile fabrication prior to October 30, 2011, both of which were also met. Chevron is required to provide the BOEM with periodic updates on
the progress of the redevelopment of Eugene Island and to meet each of the SOP activity schedule deadlines to maintain the SOP. The second SOP (December 1, 2010 through
October 31, 2011) expired on October 31, 2011. A third SOP was requested and was granted covering the period of time from October 31, 2011, through August 31, 2012. The
third SOP requires meeting development and construction milestones prior to August 31, 2012, with the restoration of production in October 2012. An application for a fourth SOP will be required
to cover the period of time from August 31, 2012 through October 2012. Chevron has stated it intends to redevelop Eugene Island 338 and 339, and has met the requirements set forth in the first
SOP and in the second SOP; however, there is no assurance that a subsequent SOP will be sought or if sought, approved by the BOEM. Likewise, there is no obligation upon Chevron to continue to pursue
the redevelopment of Eugene Island 338 and 339.

In
December 2009, Chevron entered into a participation agreement with a third party to assist in the redevelopment of Eugene Island 338 and 339. The redevelopment plan provided that
three wells were to be drilled from a common open water location in Eugene Island 338 in the second quarter of 2010. The first well of the three-well drilling program had been drilled;
however, drilling activity was suspended and the drilling rig moved off location in July 2010. Chevron's inability to obtain related drilling permits in a timely basis under the new guidelines issued
by the BOEM on June 8, 2010, following the oil spill in the U.S. Gulf of Mexico related to the sinking of the Deepwater Horizon drilling rig, pursuant to Notice to Lessees
No. 2010-N05, "Increased Safety Measures for Energy Development on the OCS", caused the parties to such participation agreement to revise and amend the participation agreement. The
revised redevelopment plan provides for setting a platform at Eugene Island 338 and drilling wells into Eugene Island 339 and Eugene Island 338 from such platform. The revised redevelopment plan
retains the original estimate for first production from Eugene Island 339 of the fourth quarter of 2012.

By
letter dated May 9, 2011, Chevron informed the Trust that, under such participation agreement with the third party, the third party holds the right to earn an assignment of 65%
of Chevron's working interest in the Eugene Island 339 properties. Chevron holds a 50% interest in Eugene Island 339, which interest is included in the 5500' and the 4500' sand units; 42.05% of all
production from the 5500' sand unit is allocated to Eugene Island 339 and 38.50% of the gas production and 24.44% of the oil production from the 4500' sand unit is allocated to Eugene Island 339.
Pursuant to the terms of the Conveyance, Chevron may enter into a farmout agreement whereby Chevron assigns any portion of its interest in the Royalty Properties free and clear of the Royalty, and the
Royalty will be reduced in the same proportion as that in which the Royalty Property is reduced. Under the terms of the Conveyance, a "farmout agreement" is defined as an agreement with a third party
requiring or permitting the

15

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performance
of drilling or development operations on a Royalty Property, and for which all or substantially all of the consideration is the transfer of an interest in a Royalty Property. Because
Chevron's working interests will, with an earning by the third party under such participation agreement, be reduced by 65%, the Royalty held by the Partnership with respect to such properties will,
effective as of the date of any earning as provided for in the assignment, be reduced proportionately. According to Chevron, as a result of any assignment that may be earned and delivered under such
participation agreement, neither Chevron nor the Trust will, except in the event of any subsequent amendment(s) of the participation agreement, bear the cost of the redevelopment of Eugene Island 339
under the terms of such participation agreement. Chevron and the Trust will bear the proportionately reduced post-redevelopment costs incurred for each Eugene Island 339 Royalty Property.

Restoration
of production at Eugene Island 338 and 339 is a complex process, requires various governmental permits, and cannot be assured at this time. The costs for the redevelopment
project would be significant. Failure or inability to pursue such a redevelopment, or to satisfy the activity schedule approved by the BOEM, could result in a loss of the lease covering Eugene Island
339. At this time, there is and can be no assurance that each activity schedule date will be met or that an additional SOP will be approved by the BOEM or that production will be restored at Eugene
Island 339. Additionally, the Trust cannot predict at this time the further impact that the oil spill in the U.S. Gulf of Mexico related to the sinking of the Deepwater Horizon drilling rig may have
on the redevelopment of Eugene Island 339.

Production
at Ship Shoal 182/183 ceased following damage inflicted by Hurricane Ike in September 2008. While the hurricane caused limited surface damage to the facilities at Ship Shoal
182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. Crude oil revenues from Ship Shoal
182/183 represented approximately 50% of the crude oil and condensate revenues for the Royalty Properties in 2007 and approximately 51% of such revenues for the nine months ended September 30,
2008. Ship Shoal 182/183 contributed approximately 77% of the revenues from natural gas sales from the Royalty Properties in 2007 and approximately 42% of such revenues for the nine months ended
September 30, 2008. A limited volume of oil production was restored in November 2008. The volume of oil production that
can be produced is limited by the amount of gas that is also produced by the oil wells. The third-party transporter's natural gas pipeline repairs were completed and gas sales at Ship Shoal 182/183
were restored on June 26, 2009. However, the pipeline was shut down in mid-September 2009 for additional repairs. Production sales for both oil and natural gas at Ship Shoal 182 and
183 were restored on October 8, 2009 following completion of such additional repairs. Oil and gas production at Ship Shoal 182/183 ceased in March 2010 due to a leak in the oil pipeline that
services Ship Shoal 182/183. Such oil pipeline was subsequently repaired and Ship Shoal 182/183 was reopened on May 1, 2010 after a 36-day shut-in. In November 2010, the
platform at Ship Shoal 182/183 was shut-in for a scheduled tank replacement.

In
addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. Chevron,
as the Managing General Partner of the Partnership, understands that, as a result of the cessation of production at West Cameron 643 due to the damages inflicted by Hurricane Ike to a third-party
transporter's pipeline, Hilcorp submitted to the BOEM a program to restore production at West Cameron 643 and such request was granted. The approval by the BOEM expired by its terms on May 31,
2010, and Chevron has been informed by Hilcorp that it submitted to the BOEM a request for

16

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an
extension but that such request was denied. Accordingly, the lease for West Cameron 643 expired on May 31, 2010. Chevron has been informed by Hilcorp that it is in the process of plugging
and abandoning the wells at West Cameron 643, which is expected to be completed by February 15, 2012, and infrastructure removed by June 30, 2012, and that Hilcorp would then remove the related
infrastructure by the end of 2011. The field operator for East Cameron 371 has reported to Chevron that a review of the remaining reserves for East Cameron 371 has been conducted, and that the wells
at East Cameron 371 have been depleted. The lease for East Cameron 371 expired on March 31, 2010 and field abandonment work, including the related wells, equipment platforms and any field
infrastructure, remains to be completed.

In
January 2010, the Trust engaged an independent oil and gas accounting firm to review the books and records of certain Working Interest Owners with respect to the Royalty Properties
and the related payments to the Trust. Such audit review process is currently on-going and may result in certain adjustments to revenues, production volumes, prices and expenditures. As
part of such process, Chevron has agreed that $22,197 in adjustments were appropriate, which were credited in the first quarter of 2011. Chevron did not pay this amount to the Partnership or the
Trust, but credited such amount against the Partnership's share of allocated expenses for the Royalty Properties. Chevron has also agreed that $608,409 of expenses with respect to Eugene Island 339 in
the first quarter of 2009 that were previously allocated to the Partnership should have been charged to Chevron. Credit for $287,594 of such amount was made in the second quarter of 2011, with the
remaining $320,815 credited in the third quarter of 2011. No assurance can be provided as to the ultimate outcome of such audit review process.

Three Months Ended September 30, 2011 and 2010

The following operational information has been based on information provided to the Corporate Trustee by Chevron as the Managing
General Partner of the Partnership. The Trustees have no control over these operations or internal controls relating to this information.

Volumes and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.

Ship
Shoal 182/183 crude oil revenues increased from $3,259,209 in the third quarter of 2010 to $4,956,353 in the third quarter of 2011, due primarily to an increase in realized oil
prices. Net crude oil production increased from 40,666 barrels in the third quarter of 2010 to 42,147 barrels in the third quarter of 2011. The increase in volumes is due primarily to increased
production at Ship Shoal 182/183, although such production for each of the two periods was affected by necessary repairs. Production ceased at Ship Shoal 182/183 for 36 days starting in late
March 2010 due to a leak in the oil pipeline that services Ship Shoal 182/183. Ship Shoal was again shut-in during November 2010 for a tank replacement and production slowly returned
thereafter. The average crude oil price received increased from $80.15 per barrel in the third quarter of 2010 to $117.60 per barrel for the same period in 2011. Gas revenues decreased from $218,627
in the third quarter of 2010 to $118,335 in the third quarter of 2011. Gas production decreased from 47,160 Mcf in the third quarter of 2010 to 24,538 Mcf in the third quarter of 2011. Capital
expenditures increased from $154,983 in the third quarter of 2010 to $324,725 in the third quarter of 2011 primarily due to certain facility improvement projects. Operating expenses decreased from
$1,526,681 in the third quarter of 2010 to $1,384,432 for the same period in 2011.

17

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Eugene
Island 339 net crude oil revenues were $0 in the third quarter of 2010 and 2011 due to suspended drilling activity and, therefore, no production in the third quarter of 2011 and
2010. Gas revenues were $0 in the third quarter 2010 and 2011 also as a result of the suspended drilling and, therefore, no gas production during the third quarter of 2010 and 2011. Capital
expenditures were $0 in the third quarter of 2010 and $0 in the third quarter of 2011. Operating expenses decreased from
$5,259,967 in the third quarter of 2010 to $4,924,382 in the third quarter of 2011 due primarily to less well and platform abandonment work being conducted at Eugene Island 339 in the third quarter of
2011 as compared to the third quarter of 2010.

West
Cameron 643 gas revenues were $0 in the third quarter of 2010 and 2011. Gas volumes were 0 Mcf in the third quarter of 2010 and 2011. There was no actual gas production during the
third quarter of 2010 and 2011as a result of the field being shut-in following Hurricane Ike in September 2008. Operating expenses increased from $13,391 in the third quarter of 2010 to
$2,391,767 for the same period in 2011. Capital expenditures were $0 in the third quarter of 2010 and 2011.

East
Cameron 371 crude oil revenues were $0 in the third quarter of 2010 and 2011 as a result of the field being shut-in following Hurricane Ike in September 2008. Production
was 0 barrels in the third quarter of 2010 and 2011. Gas revenues were $0 in the third quarter of 2010 and 2011 as a result of no gas volumes in the third quarter 2010 and 2011. Operating expenses and
capital expenditures were $0 in the third quarter of 2010 and 2011.

South
Timbalier 36/37 crude oil revenues increased from $89,497in the third quarter of 2010 to $126,213 for the same period in 2011 due primarily to an increase in realized oil prices
partially offset by a decrease in oil production volumes. The average crude oil price received increased from $79.65 per barrel in the third quarter of 2010 to $117.45 per barrel in the third quarter
of 2011. There was a decrease in crude oil production volumes to 1,075 barrels in the third quarter of 2011 from 1,124 barrels in the third quarter of 2010. Gas revenues increased from $12,274 in the
third quarter 2010 to $14,330 in the third quarter of 2011 due primarily to an increase in natural gas volumes and an increase in gas prices realized. There was an increase in natural gas volumes from
2,816 Mcf in the third quarter of 2010 to 3,154 Mcf in the third quarter of 2011. The average natural gas price received increased from $4.36 per Mcf in the third quarter of 2010 to $4.54 per Mcf in
the third quarter of 2011. Capital expenditures decreased from $30,802 in the third quarter of 2010 to $1,701 in the third quarter of 2011, which were primarily associated with drill and well
workovers. Operating expenses increased from $7,942 in the third quarter of 2010 to $14,895 in the third quarter of 2011.

Nine Months Ended September 30, 2011 and 2010

Volumes and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless
otherwise specified.

Ship
Shoal 182/183 crude oil revenues increased from $9,226,960 in the first nine months of 2010 to $11,921,357 in the same period in 2011, due primarily to an increase in the average
crude oil price from $77.57 per barrel in the first nine months of 2010 to $104.35 per barrel for the same period in 2011. This increase was partially offset by a decrease in net crude oil production
from 118,950 barrels in the first nine months of 2010 to 114,239 in the same period of 2011. Production ceased at Ship Shoal 182/183 for 36 days starting in late March 2010 due to a leak in the
oil pipeline that services Ship Shoal 182/183. Ship Shoal was again shut-in during November 2010 for a tank replacement and production slowly returned thereafter. Gas revenues decreased
from $1,006,631in the first nine months

18

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of
2010 to $440,167 in the same period of 2011. Gas production decreased from 199,539 Mcf in the first nine months of 2010 to 105,143 Mcf in the same period of 2011. The natural gas sales price was
$5.04 per Mcf in the first nine months of 2010 compared to $4.19 per Mcf in the first nine months of 2011. Capital expenditures increased from $243,438 in the first nine months of 2010 to $956,995 in
the same period of 2011, due primarily to tank and panel upgrades during the first nine months of 2011. Operating expenses increased from $3,045,054 in the first nine months of 2010 to $3,279,122 for
the same period in 2011 primarily due to a routine wireline support expense project and workover expenses associated with the I-4 ST well.

Eugene
Island 339 net crude oil revenues were $0 in the first nine months of 2010 and in 2011. Production was 0 barrels in the first nine months of 2010 and 2011. Gas revenues were $0 in
the first nine months 2010 and 2011. Production was 0 Mcf in the first nine months of 2010 and 2011. Capital expenditures increased from $(8,582) in the first nine months of 2010 to $0 in the same
period in 2011. Capital expenditures for the first nine months of 2010 reflect credits of $8,582 associated with the workover of a well during a prior period and an invoice correction related to well
abandonment. Operating expenses increased from $10,944,143 in the first nine months of 2010 to $11,628,876 in the same period in 2011, due primarily to more well and platform abandonment work being
conducted in the first nine months of 2011 as compared to the first nine months of 2010.

West
Cameron 643 gas revenues decreased from $5,244 in the first nine months of 2010 to $0 for the same period in 2011. Gas volumes were 0 Mcf in the first nine months of 2010 and 2011.
There was no actual gas production during the first nine months of 2010 as a result of the field being shut-in following Hurricane Ike in September 2008 as a result of damages to a
third-party transporter's pipeline. The positive revenues for the first nine months of 2010 are the result of a correction to a prior period audit adjustment made in the first quarter of 2009.
Operating expenses increased from $173,152 for the first nine months of 2010 to $3,790,309 for the same period in 2011, and are associated with abandonment costs at West Cameron 643. Capital
expenditures were $0 for the first nine months of 2010 and 2011.

East
Cameron 371 crude oil revenues were $0 for the first nine months of 2010 and 2011 as a result of the field being shut-in following Hurricane Ike in September 2008.
Production was 0 barrels in the first nine months of 2010 and 2011. Gas revenues were $0 for the first nine months of 2010 and 2011 as a result of no volumes in the first nine months of 2010 and 2011.
Capital expenditures were $0 in the first nine months of 2010 and 2011. Operating expenses were $0 in the first nine months of 2010 and 2011.

South
Timbalier 36/37 crude oil revenues increased from $256,874 in the first nine months of 2010 to $367,274 for the same period in 2011 due primarily to an increase in the average
crude oil price received from $77.08 per barrel in the first nine months of 2010 to $101.65 per barrel for the same period in 2011. There was also an increase in crude oil production volumes to 3,613
barrels in the first nine months of 2011 from 3,333 barrels in the first nine months of 2010. Gas revenues increased from $34,207 in the first nine months of 2010 to $38,537 in the first nine months
of 2011. There was an increase in natural gas volumes from 7,114 Mcf in the first nine months of 2010 to 9,037 Mcf in the first nine months of 2011. The natural gas sales price was $4.81 per Mcf in
the first nine months of 2010 compared to $4.26 per Mcf in the first nine months of 2011. Capital expenditures decreased from $46,921 in the first nine months of 2010 to $35,665 in the first nine
months of 2011. Operating expenses increased from $27,070 in the first nine months of 2010 to $31,248 in the first nine months of 2011.

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Liquidity and Capital Resources

The Trust's source of capital is the Royalty income received from its share of the Net Proceeds from the Royalty Properties. Total
future net revenues attributable to the Partnership's interest in the Royalty were estimated at $19.8 million as of October 31, 2010. However, there are not likely to be sufficient Net
Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly distribution to Unit holders for the foreseeable future. Chevron offered to the Trustees in February 2011
that, based on then present production forecasts, the possibility of distributions being made to the Partnership would likely begin in 2013. However, there can be no assurance by Chevron or anyone
else as to the actual timing for any future distributions to the Partnership from the Royalty, and distributions could recommence some time before, during or after 2013, and there is no guarantee that
any further distributions will be made.

Because
of the lack of receipt of Net Proceeds, the Trust has not had sufficient cash flow to pay expenses on a current basis. The Trust Agreement provides that, if necessary to provide
for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders (a) sell all or a portion of the Trust's interest in the Partnership or any
other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise their rights under the Partnership Agreement to dissolve the Partnership, or
(c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

On
March 11, 2011, the Trustees provided written notice to Chevron that, pursuant to the Trust Agreement, the Trust needed funds to pay for liabilities of the Trust and that the
Trustees therefore instructed Chevron, as the Managing General Partner of the Partnership, to sell such portion, and only such portion, of the Royalty that will provide the Trust with a current
distribution equal to $2,000,000 from the proceeds of such sale. Based on a recommendation from Chevron, as the Managing General Partner of the Partnership, Chevron marketed for sale by the
Partnership the entire Royalty, while reserving the right to sell only a portion of the Royalty. Chevron engaged EnergyNet.com, Inc. to
conduct the marketing process and the related auction for the Royalty, with the bids in the auction due on August 30, 2011. EnergyNet.com, Inc. is a FINRA-registered broker dealer that
provides marketing services to the oil and gas industry.

On
October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale of 20% of the Royalty. The sale generated $1,600,000 in gross
proceeds and occurred as part of such formal auction process for the Royalty. The Trust received from the Partnership a distribution of approximately $1,485,851, representing 99.99% of the net
proceeds from the sale of $1,486,000. The Trust will use such net proceeds solely for the payment of expenses of the Trust.

The
sale is governed by a letter agreement, pursuant to which the Partnership and RNR Production, Land and Cattle Company, Inc. ("Purchaser") made various representations and
warranties, with related indemnification obligations. In connection therewith, the Partnership and Purchaser executed a Partial Assignment of Overriding Royalty Interests.

The
sale was made to Purchaser on October 27, 2011, though the assignment of the 20% is effective as of August 1, 2011. Purchaser initially required a minimum purchase of
25% of the Royalty. Pursuant to an Option Agreement, the Partnership has agreed with Purchaser that if the Partnership elects to sell, or market for sale, any portion of the Royalty on or prior to
December 31, 2012, Purchaser will have the option to acquire such percentage interest, up to an additional 5% of the entire

20

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Royalty,
for a sales price equivalent to the product of $80,000 times the percentage interest acquired. In order to exercise the option, Purchaser would have to provide the Partnership notice of such
exercise within 10 days following the Partnership's notice to Purchaser of such proposed sale.

On
October 7, 2008, the Trust announced that production from the two most significant oil and gas properties associated with the Trust had ceased following damage inflicted by
Hurricane Ike in September 2008. On December 19, 2008, the Trust announced its fourth quarter distribution of approximately $0.7 million, which was paid on January 9, 2009. Based
on the damage caused by Hurricane Ike, the Trust's scheduled distribution for the fourth quarter of 2008 was severely negatively impacted, although there were funds available for distribution given
that there was some production from Eugene Island 339 and Ship Shoal 182/183 in August and September 2008. The Trust has not received a distribution of Net Proceeds since December 2008. Consequently,
the Trust has not made a distribution to Unit holders for eleven consecutive quarters, or since January 9, 2009. As a result of the damage inflicted by Hurricane Ike, Net Proceeds will continue
to be severely impacted by reduced production, from historical levels, and the amount of expenditures incurred that are associated with
such damages, including the expenditures required to plug and abandon the wells on Eugene Island 339 and to redevelop the facility at Eugene Island 339. While Chevron has stated that it intends to
redevelop Eugene Island 339, there is no obligation for Chevron to continue to pursue such redevelopment.

The
platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike. Chevron is working on the plugging and abandonment of the existing wells, clearing debris and
otherwise dealing with the remaining infrastructure, which activities are not expected to be completed until the second quarter of 2012. Chevron has informed the Corporate Trustee that Chevron
presently intends to pursue the redevelopment of platforms and wells at Eugene Island 339 in accordance with the terms and conditions established by the BOEM in response to Chevron's submission to the
BOEM of a program to restore production at Eugene Island 339; however, there is no obligation for Chevron to pursue such redevelopment. The costs for the redevelopment would be significant. Failure or
inability to pursue such a redevelopment, and on the timeframes approved by the BOEM, could result in a loss of the lease. At this time, there can be no assurance that production will be restored at
Eugene Island 339. Chevron has informed the Trust that, under a participation agreement with a third party, the third party holds the right to earn an assignment of 65% of Chevron's working interest
in the Eugene Island 339 properties. Because Chevron's working interests will, with an earning by the third party under such participation agreement, be reduced by 65%, the Royalty held by the
Partnership with respect to such properties will, effective as of the date of any earning as provided for in the assignment, be reduced proportionately. According to Chevron, as a result of any
assignment that may be earned and delivered under such participation agreement, neither Chevron nor the Trust will, except in the event of any subsequent amendment(s) of the participation agreement,
bear the cost of the redevelopment of Eugene Island 339 under the terms of such participation agreement. See "Operational Review" for a more detailed discussion of Eugene Island 339.

Production
at Ship Shoal 182/183 ceased following damage inflicted by Hurricane Ike in September 2008. While the hurricane caused limited surface damage to the facilities at Ship Shoal
182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. The third-party transporter's natural
gas pipeline repairs were completed and gas sales at Ship Shoal 182/183 were restored on June 26, 2009. However, the pipeline was shut down in mid-September 2009 for additional
repairs. Production sales for both oil and natural

21

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gas
at Ship Shoal 182 and 183 were restored on October 8, 2009 following completion of such additional repairs. Production ceased at Ship Shoal 182/183 in late March 2010 due to a leak in the
oil pipeline that services Ship Shoal 182/183. Such pipeline was repaired and Ship Shoal 182/183 was reopened on May 1, 2010 after a 36-day shut-in. See
"Operational Review" for a more detailed discussion of Ship Shoal 182/183.

In
addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. Chevron
has been informed by the operator of West Cameron 643 that the operator submitted to the BOEM a request for an extension of the program to restore production but that such request was denied.
Accordingly, the lease for West Cameron 643 expired on May 31, 2010. The field operator for East Cameron 371 has reported to Chevron that a review of the remaining reserves for East Cameron 371
has been conducted, and that the wells at East Cameron 371 have been depleted. The lease for East Cameron 371 expired on March 31, 2010. See "Operational Review" for a more
detailed discussion of West Cameron 643 and East Cameron 371.

Future
Net Proceeds from the Royalty Properties will take into account the Trust's share of project costs and other related expenditures that are not covered by the insurance of the
operators of the Royalty Properties. Chevron has informed the Trustees that Chevron has reached settlements that provide Chevron with insurance proceeds associated with damages that Chevron's assets
sustained from Hurricane Ike, and that the allocated portion thereof with respect to the Partnership's interest in Eugene Island 339, as a Royalty Property, is approximately $612,000. Chevron applied
$400,000 thereof in the first quarter of 2011 and has stated that the remaining approximately $212,000 is to be received by Chevron and allocated to the Partnership's interest upon completion of the
abandonment work at Eugene Island, which is expected to occur in the second quarter of 2012. Chevron has stated that all such allocated insurance proceeds will be applied to the Partnership's portion
of the aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339. In September 2011, Chevron informed the Trust that the estimate of the Trust's net portion of the
aggregate cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased from approximately $15 million to approximately $16.5 million, approximately
$14.2 million of which had been incurred through July 31, 2011, without taking into account the benefit of such allocated insurance proceeds. If Production Costs of the Royalty
Properties exceed the Gross Proceeds from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued
interest at a rate equal to one-fourth of (i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in
which there are excess costs and the prime interest rate at the end of the preceding quarterly period, during the deficit period. As a result of the damage inflicted by Hurricane Ike, the Trust has
not received Net Proceeds since December 2008. As of July 31, 2011, aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related proceeds
of production from the Royalty Properties by approximately $4.2 million. In the fourth quarter of 2010, Chevron withdrew $4,304,894 from the Special Cost Escrow account of the Working Interest
Owners (a reserve fund for certain costs) to cover expenses incurred in connection with the plugging and abandonment of Eugene Island 339, which served to reduce the amount by which production costs
exceeded the proceeds from production as of December 31, 2010; however, additional deposits to the Special Cost Escrow account would be required in future periods in accordance with the terms
of the Conveyance if, and when, Net Proceeds would otherwise be payable on the Royalty. Significant development and production costs will continue to be incurred if Eugene Island 339 is redeveloped.
Accordingly, there will not be sufficient

22

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Net
Proceeds from the Royalty Properties to make distributions for some period of time in the future. At this time, the ultimate outcome of these various matters cannot be determined. See
"Operational Review."

Substantial
uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions
taken by major petroleum producing nations, as well as the regional supply and demand for oil and gas, worldwide political conditions, weather, industrial growth, conservation measures, competition,
economic conditions generally and other variables.

In
accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and any cash reserves
established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. In 1994, in anticipation of future periods when the cash received from the
Royalty may not be sufficient for payment of Trust expenses, the Trust determined, in accordance with the Trust Agreement, to begin further increasing the Trust's cash reserve each quarter. In the
first quarter of 1998, the Trust determined that the Trust's cash reserve was then sufficient to provide for future administrative expenses in connection with the winding up of the Trust. The Trust
determined that a cash reserve equal to three times the average expenses of the Trust during each of the past three years was sufficient at such time to provide for future administrative expenses in
connection with the winding up of the Trust.

The
reserve amount at September 30, 2011 was approximately $6,580, or approximately 1% of the average annual expenses of the Trust during the three-year period ended
September 30, 2011. As of September 30, 2011, the Trust had additional expenses of approximately $432,000 in the aggregate that had not been paid. The reserve amount at
December 31, 2010 was $352,017, or approximately 39% of the average annual expenses of the Trust during the three-year period ended December 31, 2010. As described herein,
there are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. Because of the lack of receipt of Net Proceeds, the Trust, prior to the sale of 20% of the
Royalty by the Partnership, did not have sufficient cash flow to pay expenses on a current basis.

Pursuant
to the terms of the Trust Agreement, the Trustees, on behalf of the Trust, are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such
borrowings, in the event that cash on hand is not sufficient to pay the liabilities of the Trust. In the event that the Trustees borrow funds to pay the liabilities of the Trust, no distributions will
be made to the Unit holders until the indebtedness created by such borrowings has been paid in full.

The
Trust Agreement further provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders
(a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise
their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

The
Trustees of the Trust have previously asked Chevron if it would be willing to advance funds to the Partnership against future payments to the Partnership on the Royalty, particularly
in light of Chevron's withdrawal of $4,304,894 from the Special Cost Escrow account in the fourth quarter of 2010. Chevron declined to make any such advance of funds, though orally offered to the
Corporate Trustee in December 2010 to buy the Royalty for $0. As discussed under "Operational Review", in

23

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January
2010, the Trust engaged an independent oil and gas accounting firm to review the books and records of certain Working Interest Owners with respect to the Royalty Properties and the related
payments to the Trust. The Corporate Trustee has requested Chevron to pay any adjustments resulting from such audit directly to the Partnership; however, Chevron instead intends to credit any such
adjustments against the Partnership's share of allocated expenses for the Royalty Properties. As a result, there will be no current payments to the Partnership resulting from such audit.

In
March 2011, the Trustees unanimously determined to suspend further payments of fees to the Trustees, until a date to be determined in the future by the Trustees. Such suspended fees
were accrued as an expense of the Trust, but were not be paid currently, until November 2011, when such fees were paid following receipt by the Trust of proceeds from the sale of a portion of the
Royalty by the Partnership in late October 2011.

The
accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. The lack of Net Proceeds and the inability to maintain adequate cash
reserves raise substantial doubt about the Trust's ability to continue as a going concern (see Notes 4 and 6 to the financial statements). The financial statements do not include any
adjustments that might result from the outcome of this uncertainty.

Future Net Revenues and Termination of the Trust

Based on a reserve study provided to Chevron, as the Managing General Partner of the Partnership, by DeGolyer and MacNaughton,
independent petroleum engineers, as of October 31, 2010 future net revenues attributable to the Trust's royalty interests were estimated at $19.8 million. Estimates of proved oil and gas
reserves attributable to the Partnership's royalty interest are based on existing economic and operating conditions in effect at October 31, 2010 in order to correspond with distributions to
the Trust. Such reserve study also indicates that approximately 66% of the future net revenues from the Royalty Properties are expected to be received by the Trust by October 31, 2012. The
reserve study does not include reserves attributable to Eugene Island 339 or any capital expenditures for any redevelopment of Eugene Island 339. However, such reserve study does include the Trust's
share of the estimated total plugging and abandonment costs related to Eugene Island 339. In September 2011, Chevron informed the Trust that the estimate of the Trust's net portion of the aggregate
cost to plug and abandon the wells subject to the Royalty on Eugene Island 339 had increased from approximately $15 million to approximately $16.5 million, approximately
$14.2 million of which had been incurred through July 31, 2011, and without giving credit for an expected approximately $612,000 of insurance proceeds received, or to be received, by
Chevron and allocated for the benefit of the Partnership with respect to Eugene Island 339. Because the Trust will terminate in the event estimated future net revenues fall below $2.0 million,
it would be possible for the Trust to terminate even though some or all of the Royalty Properties continued to have remaining productive lives. Upon termination of the Trust, the Trustees will sell
for cash all of the assets held in the Trust estate and make a final distribution to Unit holders of any funds remaining after all Trust liabilities have been satisfied. The estimates of future net
revenues discussed above are subject to large variances from year to year and should not be construed as exact. There are numerous uncertainties present in estimating future net revenues for the
Royalty Properties. The estimate may vary depending on changes in market prices for crude oil and natural gas, the recoverable reserves, annual production and costs assumed by DeGolyer and
MacNaughton. In addition, future economic and operating conditions as well as results of future drilling plans may cause significant changes in such estimate. The discussion set forth above is

24

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qualified
in its entirety by reference to the Trust's Annual Report on Form 10-K for the year ended December 31, 2010. The Trust's Form 10-K is available
at the website of the Securities and Exchange Commission ("SEC") atwww.sec.govor upon request from the Corporate Trustee.

Special Cost Escrow Account

The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling
platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in
the Conveyance, the amount of funds to be reserved is determined based on factors including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net
revenues and actual current net proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit.
Such account is herein referred to as the "Special Cost Escrow" account. The Trust's share of interest generated from the Special Cost Escrow account serves to reduce the Trust's share of allocated
production costs. Special Cost Escrow funds will generally be utilized to pay Special Costs to the extent there are not adequate current net proceeds to pay such costs. Special Costs that have been
paid are no longer included in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost Escrow account is less than
125% of estimated future Special Costs and there is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained
in the Conveyance). When there is not a Net Revenues Shortfall, amounts in the Special Cost Escrow account will generally be released, to the extent that Special Costs have been incurred. Amounts in
the Special Cost Escrow account will also be released when the balance in such account exceeds 125% of estimated future Special Costs. In the third quarter of 2011, there were no funds released or
escrowed from the Special Cost Escrow account. As of September 30, 2011, $1,000 remained in the Special Cost Escrow account. None of the funds held in the Special Cost Escrow account are
reflected in the financial statements of the Trust. The discussion of the terms of the Conveyance and Special Cost Escrow account contained herein is qualified in its entirety by reference to the
Conveyance itself, which is an exhibit to this Form 10-Q and is available upon request from the Corporate Trustee.

In
the fourth quarter of 2010, Chevron withdrew $4,304,894 from the Special Cost Escrow account of the Working Interest Owners (a reserve fund for certain costs) to cover expenses
incurred in connection with the plugging and abandonment of Eugene Island 339, leaving a balance of $1,000 in the Special Cost Escrow account. After taking into account such withdrawal, aggregate
development and production costs in excess of the related proceeds for the royalty properties, as of July 31, 2011, was approximately $4.2 million, net to the royalty interest; however,
additional deposits to the Special Cost Escrow account would be required in future periods in accordance with the underlying conveyance of the royalty if, and when, net proceeds would otherwise be
payable on the royalty. In the third quarter of 2011, there were no funds released from or escrowed into the Special Cost Escrow account. As of September 30, 2011, $1,000 remained in the
Special Cost Escrow account.

In
connection with the sale of 20% of the Royalty by the Partnership in October 2011, the Partnership also assigned 20% of its rights and obligations with respect to the Special Cost
Escrow. See Note 7Subsequent Events.

Chevron,
in its capacity as Managing General Partner of the Partnership, has advised the Trust that additional deposits to the Special Cost Escrow account may be required in future
periods in connection

25

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with
other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a significant reduction in
Royalty income in the periods in which such deposits are made, including the possibility that no Royalty income would be received in such periods.

Overview of Production, Prices and Royalty Income

The following schedule provides a summary of the volumes and weighted average prices for crude oil and condensate and natural gas
recorded by the Working Interest Owners for the Royalty Properties, as well as the Working Interest Owners' calculations of the Net Proceeds and the royalties paid to the Trust during the periods
indicated. Net Proceeds due to the Trust are calculated for each three month period commencing on the first day of February, May, August and November.

Royalty Properties Three
Months Ended September 30,(1)2011

2010Crude oil and condensate (bbls)


43,221


42,811Natural gas and gas products (Mcfe)


29,777


61,204Crude oil and condensate average price, per bbl

$
117.59

$
79.91Natural gas average price, per Mcf (excluding gas products)

$
4.79

$
4.55Crude oil and condensate revenues

$
5,082,567

$
3,420,889Natural gas and gas products revenues


151,207


298,575Production expenses


(6,680,226
)

(7,115,834
)Capital expenditures


(326,427
)

(185,785
)Interest


(25,581
)

Undistributed net loss (income)(2)


1,798,460


3,573,884Refund of (provision for) Special Cost Escrow





8,271Net Proceeds





Royalty interest


x25
%

x25
%Partnership share





Trust interest


x99.99
%

x99.99
%Trust share of Royalty income

$


$



(1)Amounts
are based on actual production for the three-month period ended July 30 of each year, respectively.(2)Undistributed
net loss represents the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the
Royalty Properties during the period. An undistributed net loss is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will
not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest. Undistributed net income represents positive Net Proceeds,
generated during the respective period, but not distributed by the Working Interest Owners.


26

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Royalty Properties Nine
Months Ended September 30,2011

2010Crude oil and condensate (bbls)


117,850


123,586Natural gas and gas products (Mcfe)


119,243


231,188Crude oil and condensate average price, per bbl

$
104.27

$
77.49Natural gas average price, per Mcf (excluding gas products)

$
4.19

$
5.31Crude oil and condensate revenues

$
12,288,631

$
9,576,368Natural gas and gas products revenues


526,191


1,227,465Production expenses


(15,801,648
)

(14,948,367
)Capital expenditures


(992,662
)

(281,778
)Interest


(68,970
)

Undistributed net loss (income)(1)


4,042,142


4,417,280Refund of (provision for) Special Cost Escrow


6,316


9,032Net Proceeds





Royalty interest


x25
%

x25
%Partnership share





Trust interest


x99.99
%

x99.99
%Trust share of Royalty Income

$


$



(1)Undistributed
net loss represents the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the
Royalty Properties during the period. An undistributed net loss is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will
not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest. Undistributed net income represents positive Net Proceeds,
generated during the respective period, but not distributed by the Working Interest Owners.


Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

The only assets of and sources of income to the Trust are cash and the Trust's interest in the Partnership, which is the holder of the
Royalty. Consequently, the Trust is exposed to market risk associated with the Royalty from fluctuations in oil and gas prices. Reference is also made to Note 2 of the Notes to Financial
Statements included in Item 1 of this Form 10-Q.

The
Trust may borrow money to pay expenses of the Trust. Additionally, if development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties,
the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest, at a rate equal to one-fourth of
(i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the prime interest rate
at the end of the preceding quarterly period, during the deficit period. Consequently, the Trust will be exposed to interest rate market risk should it borrow money to pay expenses and to the extent
that development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties. As a result of the damage inflicted by Hurricane Ike, the Trust has not received Net
Proceeds since December 2008 as development and production costs of the

27

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Royalty
for each Quarterly Period since November 2008 have exceeded the proceeds of production from the Royalty Properties. As of July 31, 2011, development and production costs of the Royalty
exceeded the proceeds of production from the Royalty Properties by approximately $4.2 million after taking into account Chevron's withdrawal of $4,304,894 from the Special Cost Escrow account
of the Working Interest Owners in the fourth quarter of 2010.

Item 4.    Controls and Procedures.

Evaluation of disclosure controls and procedures.The Corporate Trustee maintains disclosure controls and procedures designed to ensure
that
information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within
the time periods specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the
Trust is accumulated and communicated by Chevron, as the Managing General Partner of the Partnership, and the Working Interest Owners to the Corporate Trustee of the Trust, and its employees who
participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure.

As
of the end of the period covered by this report, the Corporate Trustee carried out an evaluation of the Trust's disclosure controls and procedures. Mike Ulrich, as Trust Officer of
the Corporate Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.

Due
to the contractual arrangements of (i) the Trust Agreement, (ii) the Partnership Agreement and (iii) the rights of the Partnership under the Conveyance regarding
information furnished by the Working Interest Owners, the Trustees rely on (A) information provided by the Working Interest Owners, including historical operating data, plans for future
operating and capital expenditures, reserve information and information relating to projected production, (B) information from the Managing General Partner of the Partnership, including
information that is collected from the Working Interest Owners, and (C) conclusions and reports regarding reserves by the Trust's independent reserve engineers. See Item 1A. Risk Factors
"The Trustees and the Unit holders have no control over the operation or development of the Royalty Properties and have little influence over operation or development" and "The Trustees
rely upon the Working Interest Owners and Managing General Partner for information regarding the Royalty Properties" in the Trust's Annual Report on Form 10-K for the year ended
December 31, 2010 for a description of certain risks relating to these arrangements and reliance on and applicable adjustments to operating information when reported by the Working Interest
Owners to the Corporate Trustee and recorded in the Trust's results of operation.

Changes in Internal Control Over Financial Reporting.During the three months ended September 30, 2011, there has been no change in
the
Trust's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. The Corporate
Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of the Working Interest Owners or the
Managing General Partner of the Partnership.

28

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PART IIOTHER INFORMATION

Item 1A.    Risk Factors.

The Trust continues to utilize its cash reserves to pay expenses, and there are not likely to be Net Proceeds
distributed to the Trust for the foreseeable future. Because of the lack of receipt of Net Proceeds, the Trust has not had sufficient cash flow to pay expenses on a current basis. While the Trust has
realized proceeds of approximately $1,485,851 from the sale by the Partnership of 20% of the Royalty, the Trust may in the future still not have sufficient cash flow to pay expenses on a current
basis. As a result of such sale, the Partnership will receive in the future only 80% of the Net Proceeds when there are sufficient Net Proceeds for distribution on the Royalty.

The
Trust's source of capital is the Royalty income received from its share of the Net Proceeds from the Royalty Properties. The Trust has not received a distribution of Net Proceeds
since December 2008, and there are not likely to be positive Net Proceeds from the Royalty Properties for the foreseeable future. The Trust continues to utilize its cash reserves to pay expenses;
however, as of September 30, 2011, those reserves were approximately 1% of the average annual expenses of the Trust during the three-year period ended September 30, 2011. As
of September 30, 2011, the Trust had additional expenses of approximately $432,000 in the aggregate that had not been paid. Because of the lack of receipt of Net Proceeds, the Trust has not had
sufficient cash flow to pay expenses on a current basis.

On
October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale of 20% of the Royalty. The sale generated $1,600,000 in gross
proceeds and occurred as part of a previously announced formal auction process for the Royalty. The Trust received from the Partnership a distribution of approximately $1,485,851, representing 99.99%
of the net proceeds from the sale of $1,486,000. The Trust will use such net proceeds solely for the payment of expenses of the Trust. The Partnership has retained an 80% interest in the Royalty, and
thus the Partnership will receive in the future only 80% of the Net Proceeds when there are sufficient Net Proceeds for distribution on the Royalty.

Item 6.    Exhibits.

(Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference.)

SEC File or
Registration
Number4(a)*




Trust Agreement dated as of January 1, 1983, among Tenneco Offshore Company, Inc., Texas Commerce Bank National Association, as corporate trustee, and Horace C. Bailey, Joseph C. Broadus and F. Arnold Daum, as
individual trustees (Exhibit 4(a) to Form 10-K for the year ended December 31, 1992 of TEL Offshore Trust)


0-069104(b)*




Agreement of General Partnership of TEL Offshore Trust Partnership between Tenneco Oil Company and the TEL Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to Form 10-K for year ended December 31,
1992 of TEL Offshore Trust)


0-06910


29

---



SEC File or
Registration
Number4(c)*




Conveyance of Overriding Royalty Interests from Exploration I to the Partnership (Exhibit 4(c) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)


0-069104(d)*




Amendments to TEL Offshore Trust Agreement, dated December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)


0-069104(e)*




Amendment to the Agreement of General Partnership of TEL Offshore Trust Partnership, effective as of January 1, 1983 (Exhibit 4(e) to Form 10-K for the year ended December 31, 1992 of TEL Offshore
Trust)


0-0691010(a)*




Purchase Agreement, dated as of December 7, 1984 by and between Tenneco Oil Company and Tenneco Offshore II Company (Exhibit 10(a) to Form 10-K for year ended December 31, 1992 of TEL Offshore
Trust)


0-0691010(b)*




Consent Agreement, dated November 16, 1988, between TEL Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)


0-0691010(c)*




Assignment and Assumption Agreement, dated November 17, 1988, between Tenneco Oil Company and TOC-Gulf of Mexico Inc. (Exhibit 10(c) to Form 10-K for year ended December 31, 1988 of TEL Offshore
Trust)


0-0691010(d)*




Gas Purchase and Sales Agreement Effective September 1, 1993 between Tennessee Gas Pipeline Company and Chevron U.S.A. Production Company (Exhibit 10(d) to Form 10-K for year ended December 31, 1993 of
TEL Offshore Trust)


0-0691099.1*




Letter Agreement dated October 27, 2011 between TEL Offshore Trust Partnership and RNR Production, Land and Cattle Company, Inc. (Exhibit 99.2 to Form 8-K as dated October 27, 2011 of TEL Offshore
Trust)


0-0691099.2*




Partial Assignment of Overriding Royalty Interests dated October 27, 2011 between TEL Offshore Trust Partnership and RNR Production, Land and Cattle Company, Inc. (Exhibit 99.3 to Form 8-K as dated
October 27, 2011 of TEL Offshore Trust)


0-0691099.3*




Option Agreement dated October 27, 2011 between TEL Offshore Trust Partnership and RNR Production, Land and Cattle Company, Inc. (Exhibit 99.4 to Form 8-K as dated October 27, 2011 of TEL Offshore
Trust)


0-0691031




Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 200232




Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


30

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

TEL OFFSHORE TRUSTBy:

The Bank of New York Mellon
    Trust Company, N.A.
Corporate TrusteeBy:

/s/ MIKE ULRICH Mike Ulrich Vice President


Date:
November 14, 2011

The
Registrant, TEL Offshore Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no
additional signatures are available and none have been provided.

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